Improving Sweep Efficiency at the Mature Koluel Kaike and Piedra Clavada Waterflooding Projects, Argentina

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This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 107923, "New Attempt in Improving Sweep Efficiency at the Mature Koluel Kaike and Piedra Clavada Waterflooding Projects of the S. Jorge Basin in Argentina," by Pablo Adrian Paez Yanez, SPE, and Jorge Luis Mustoni, SPE, Pan American Energy; Maximo F. Relling, SPE, and Kin- Tai Chang, SPE, Nalco; and Paul Hopkinson and Harry Frampton, SPE, BP, prepared for the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, 15–18 April. Most of the mature waterflood projects in the San Jorge basin in Argentina have been affected by poor displacement and sweep efficiencies, both limiting recovery. A reactive-particulate system was tested to improve volumetric sweep efficiency. The main purpose of this field trial was to demonstrate the ability of the system to improve oil recovery by diversion of injected water into the poorly swept zones around the thief zone or streaks. Introduction The Koluel Kaike and Piedra Clavada fields are at the southern flank of the San Jorge Gulf basin, in the province of Santa Cruz, Argentina. These fields were discovered in the early 1960s and were produced under primary depletion until the mid-1980s. Thereafter, a massive waterflood was initiated to increase the relatively poor primary recovery. The project has 220 injectors, with an average injection rate of 1,600 BWPD per injector, affecting 500 producing wells. A total of 1.9 billion bbl of water has been injected, resulting in incremental recovery estimated at 75 million bbl of oil, through December 2006. However, this mature waterflood, as with many other projects in the San Jorge basin, has experienced limited recovery. Poor displacement and sweep efficiency are characteristic of these reservoirs. The Koluel Kaike reservoir has an average of 15 stacked layers, which are braided channel deposits, each 16 ft thick. Each channel is a differentiated flow unit, with individual gas/oil/water contacts, along a 3,000-ft column between 3,500 and 6,500 ft deep. Each channel is 700 to 2,300 ft wide, and they generally are not aligned vertically. In any given well, there is a series of separate layers for injection or production (flow properties have a high degree of anisotropy). For both fields, more than 400 flow units can be differentiated. Statistical estimation of the petrophysical properties indicates an average 22% porosity and 50- to 100-md permeability or the matrix rocks. The mineralogy is complex and is derived from volcanic compounds and a wide range of clays and cementing materials. This variation causes moderate complications in saturation determination from logs and/or causes formation-damage problems. There also is a wide range, and random variations, in the salinity of the relatively fresh formation water. The reservoir fluid is undersaturated at initial conditions. The primary recovery mechanism is a combination of fluid and rock expansion. Oil gravity ranges from 19 to 23°API, viscosity from 5 to 150 cp at reservoir conditions (150°F), and gas/oil ratio from 30 to 100 scf/bbl.